Thickened CO2 in gravity drainage gas injection processes

ABSTRACT

A method and a system for oil recovery are provided. An exemplary method includes injecting thickened carbon dioxide (CO 2 ) into the top of a reservoir containing oil. An interface is formed between the thickened CO 2  and the oil. The oil is mobilized by the thickened CO 2 . The mobilized oil is recovered with a recovery well drilled below the reservoir.

TECHNICAL FIELD

The present disclosure relates to CO₂ gravity drainage gas injectionprocesses for efficient oil recovery.

BACKGROUND

An oil reservoir is a subterranean formation where oil is entrapped. Theoil can be recovered using one or more recovery wells formed in thereservoir. If the oil is entrapped at a pressure greater than ambientpressure, the oil is often recovered using the reservoir pressure alone.Where the oil is entrapped at pressures below ambient pressure,secondary or tertiary (enhanced oil recovery (EOR)) techniques have beenimplemented to recover the oil. For example, one secondary techniqueinvolves injecting water into the reservoir to increase its pressure,which mobilizes some of the remaining oil.

One EOR technique is known as “gravity drainage gas injection.” Thistechnique involves injecting a gas into the reservoir, which improvesoil recovery beyond what is achieved with a secondary recoverytechnique. CO₂ gas has been used in gravity drainage gas injectionprocesses. In particular, the CO₂ is injected into the reservoir tomobilize the oil. The mobilized oil is pushed towards recovery wellssuch that “free gravity drainage” is supplemented with “forced gravitydrainage” due to the injected CO₂.

SUMMARY

Certain aspects of the invention are implemented as a method for oilrecovery. The method includes injecting thickened CO₂ into the top of areservoir containing oil; forming an interface between the thickened CO₂and the oil; mobilizing the oil; and recovering the oil with a recoverywell drilled below the reservoir.

Certain aspects of the invention are implemented as a system for oilrecovery. The system includes an injection well; a reservoir containingoil positioned below the injection well; thickened CO₂; an interfacebetween the thickened CO₂ and the oil; and a recovery well drilled belowthe reservoir.

The details of one or more implementations of the subject matter of thisspecification are set forth in the accompanying drawings and thedescription. Other features, aspects, and advantages of the subjectmatter will become apparent from the description, the drawings, and theclaims.

BRIEF DESCRIPTION OF DRAWINGS

FIG. 1 is a schematic diagram of an example system for using thickenedCO₂ in a gravity drainage gas injection process.

FIG. 2 is a schematic diagram of an example system where thickened CO₂blocks high-permeable channels.

FIG. 3 is a schematic diagram of an example system where thickened CO₂causes uniform sweep across a pay zone.

FIG. 4 is a flow chart of an example method for using thickened CO₂ in agravity drainage gas injection process.

FIG. 5 shows CO₂ viscosities at 2000 psi after being mixed withdifferent amounts of an example thickener.

FIG. 6 shows CO₂ viscosities at 2500 psi after being mixed withdifferent amounts of an example thickener.

FIG. 7 is a schematic diagram of the device used to measure the datashown in FIGS. 5 and 6 .

FIG. 8 shows the results of an experiment showing the pressure dropacross a rock sample during water injection for pre-thickened-CO₂ andpost-thickened-C₂ treatments.

DETAILED DESCRIPTION

Gravity drainage gas injection processes involve injecting a gas, suchas CO₂, into a reservoir to mobilize oil in the reservoir, allowing theoil to be recovered. Gravity drainage gas injection is typically used asan EOR process. Most gravity drainage gas injection processes have aslow response, meaning that it takes a relatively longer time afterinjecting the displacing fluids to see the impact on the oil recovery,and low oil recovery rates. The slow response and the low oil recoveryrates increase the amount of injection gas required to recover oil.These limitations have rendered gravity drainage gas injectionprocesses, including processes using CO₂, unattractive for fieldpractice and not economically feasible.

Gravity drainage gas injection processes are limited because of low gasinjection rates used. Low gas injection rates have been required to meetthe so-called “critical gas injection rate” criterion. The critical gasinjection rate is the highest-allowable gas injection rate in a gravitydrainage gas injection process that can maintain a balanced gas front byrelying on gravitational stability while lowering the viscous force withthe reduced rate of injection.

The critical gas injection rate is one of the most important operationalparameters for gravity drainage gas injection processes because itdefines the stability of the growing gas-oil interface that steadilymoves towards the recovery well. The critical gas injection rate definesthe upper limit that the injection rate in a gravity drainage gasinjection process should not exceed. If the gas injection rate exceedsthe critical gas injection rate, the gas front destabilizes, resultingin premature gas breakthrough and gas short-circuiting in the recoverywell. To avoid this issue, oil production is maintained at slow rates inthe recovery wells such that the oil production rate is balanced by theequivalent CO₂ injection volume. The interface between the advancinginjection gas and the recovered oil must be precisely controlled tostabilize gravitational forces and result in stable movement of gas-oilinterface downward with the controlled production withdrawal rate.

Critical gas injection rates are typically low, rendering gravitydrainage gas injection process impractical. Gas thickeners may be usedto increase critical gas injection rates. But despite many years ofresearch, the industry has not found a thickener that is inexpensive,environmentally-friendly, and effective—such as a thickener that candissolve in dense CO₂ at diluted concentrations and decrease themobility of the CO₂ to a level comparable to that of oil. A majorobstacle hindering these efforts has been the limited solubility ofproposed thickeners in CO₂, which restricts their ability to increasethe CO₂ viscosity and the critical gas injection rate. Prior proposedsolutions also involve costly materials and materials with environmentalconcerns (such as those associated with fluorinated thickeners), whichhave prevented their use in the oilfield.

The subject matter described in this specification can be implemented inparticular implementations, to realize one or more of the followingadvantages. The subject matter seeks to resolve the above issues byimplementing thickened CO₂ to replace prior recovery methods. In someembodiments, the techniques are used to enhance production from oilsands or other unconsolidated reservoirs. The thickened CO₂ increasesthe response and recovery rate of gas-drainage processes by increasingthe critical gas injection rate. The increased critical gas injectionrate allows for the use of higher gas injection rates. This results inincreased response due to the combined effects of forced gravitydrainage with free gravity drainage. Further, this allows higher oilproduction recovery rates, thereby increasing ultimate oil recovery inrecovery wells. The higher oil recovery rates reduce the CO₂ gasutilization per barrel of oil recovered.

In addition, CO₂ is known to be a major contributor to the greenhouseeffect and global warming. In some embodiments, environmental effects ofusing CO₂ are mitigated because it can be injected into subsurface rockshelping to reduce the amount of CO₂ in the atmosphere. Further, similarto waterless fracking operations, using thickened CO₂ instead ofwater-based chemicals, such as foams, helps minimize water consumption.

FIG. 1 is a schematic diagram of an example system for using thickenedCO₂ in a gravity drainage gas injection process. FIG. 1 includesinjection wells 100, a reservoir containing oil 102 positioned below theinjection wells 100, thickened CO₂ 104, an interface 106 between thethickened CO₂ and the oil, and a recovery well 108 drilled below thereservoir.

FIG. 1 further shows the interface 106 positioned at the top of a payzone. The pay zone includes high-permeable channels 112. The injectionwells 100 inject the thickened CO₂ 104 to create the interface 106.

FIG. 2 is a schematic diagram of an example system. Thickened CO₂ 200 isinjected into a reservoir 202 by injection wells 204. The thickened CO₂200 blocks high-permeable channels 206 in a pay zone 208. This reducesthe relative permeability of the gas and increases the critical gasinjection rate. Therefore, the thickened CO₂ 200 can be injected athigher gas injection rates to form the interface 210 quickly at the topof the pay zone 208. After thickened CO₂ 200 is injected, the oil 212 ismobilized with unthickened CO₂ and driven towards a recovery well 214 tobe drained.

In some implementations, the thickener for the CO₂ is a mixture ofdifferent compounds including copolymer of allenethers, acrylate,acrylic long carbon chain esters/benzenes, propylene carbonate/allylethyl carbonate, dimethyl carbonate, and white oil/silicon oroil/petroleum ether.

FIG. 3 is a schematic diagram of an example system. As thickened CO₂ 300is injected by injection wells 302, it creates an expanded gas chamber304 in the reservoir 306. The blockage of high-permeable channels 208,as shown in FIG. 2 , equalizes the resistances in different pathways andcreates a more uniform sweep at the interface 308, increasing sweepefficiency. The interface 308 will expand with time and the forcedgravity drainage will supplement the free gravity drainage and increasethe oil drainage rate. After thickened CO₂ 300 is injected, the oil 310is mobilized with unthickened CO₂ and driven towards a recovery well 312to be drained.

In an embodiment, the thickened CO₂ is injected at an amount of 0.1 to0.2 pore volumes. Pore volume is the volume within a certain number ofinjectors and producers and is used herein to mean the pore volume ofthe target zone and not of the entire reservoir. Further, thickened CO₂is injected by a vertical injection well. In some embodiments, thickenedCO₂ is injected by any other type of injection wells, such as ahorizontal injection well. Additionally, oil is recovered with ahorizontal recovery well. Oil is alternatively recovered by any othertype of recovery well, such as a vertical recovery well.

FIG. 4 is a flow chart of an example method for using thickened CO₂ in agravity drainage gas injection process. At block 402, thickened CO₂ isinjected into the top of a reservoir containing oil. At block 404, aninterface is formed between the thickened CO₂ and the oil. At block 406,the oil is then mobilized. At block 408, the oil is recovered with arecovery well drilled below the reservoir 408.

EXAMPLES Example 1

Preparing Thickened CO₂

TABLE 1 Thickener Property Value Molecular Weight 500,000 g/mol pH5.0-8.0 Appearance White emulsion Relative Density 0.90-1.10 SolubilitySoluble in liquid and supercritical CO₂ Dissolution speed of 1% of the≤3 minutes chemical in liquid CO2 at 25° C.

Table 1 shows properties of the thickener used in the present tests ofthe techniques. CO₂ gas with 99.50% purity was used to determine thethickener properties shown in Table 1. The thickener described isavailable commercially as a dry-fracturing fluid friction reducer andthickener under the name APFR-2 by manufacturer Beijing AP PolymerTechnology CO., LTD. The thickener is 50 vol. % of allenether, acrylate,acrylic long carbon chain ester, acrylic long, and carbon chain benzeneand 50 vol. % propylene carbonate ethyl carbonate, propylene allyl ethylcarbonate, dimethyl carbonate, white oil, silicon, and petroleum ether.Table 1 shows that the thickener has a molecular weight of 500,000g/mol, a pH of 5.0 to 8.0, a relative density of 0.90 to 1.10, and adissolution speed of less than about three minutes for one percent inliquid CO₂ at 25° C. The thickener is able to dissolve in CO₂ atconditions similar to those of oil fields.

FIG. 5 is a graph of CO₂ viscosities at 2000 psi after being mixed withdifferent amounts of the thickener. FIG. 6 is a graph of CO₂ viscositiesat 2500 psi after being mixed with different amounts of the thickener. ACambridge HTHP viscometer apparatus, as shown in the schematic of FIG. 7, was used to conduct the viscosity measurements using differentconcentrations of the thickener and at different pressures. Theobjective of the tests shown in FIGS. 5 and 6 was to measure liquid andsupercritical CO₂ viscosity at different conditions when the thickeneris added to the dense CO₂. FIGS. 5 and 6 show that the addition of thethickener to the CO₂ enhances the CO₂ viscosity significantly. As seen,CO₂ viscosity increases between about 1100 and 1250 times as a result ofadding the thickener.

Example 2

Injecting Thickened CO₂ Into a Rock Sample

TABLE 2 Permeability Permeability After a Pore Before Volume of 2Thickened Thickened CO₂ CO₂ Injection Length Diameter Porosity InjectedInjected rate Pressure Rock Inches Inches % mD mD ml/min Psi Indiana 41.5 18 58.9 1.3 5 2000 Limestone

Table 2 shows Indiana limestone properties and experimental conditions.Thickened CO₂ in the amount of a pore volume of 2 was injected into theIndiana limestone sample. The thickened CO₂ was a mixture of 2 vol. % ofthe thickener and 98 vol. % supercritical CO₂. The thickened CO₂ reducedthe permeability of the rock from 58.9 mD (at 0 pore volumes thickenedCO₂) to 1.3 mD (at 2 pore volumes thickened CO₂). This is about a 45times reduction.

FIG. 8 shows the results of an experiment showing the pressure dropacross the Indiana limestone sample of Table 2 during water injectionfor pre-thickened-CO₂ and post-thickened-CO₂ treatments. First, theIndiana limestone was injected with water in the amount of two porevolumes. The water injection was a baseline test used for a comparisonpurpose to model the initial state of the reservoir. The water injectedwas seawater similar to that used in the fields. As seen, the pressuredrop across the Indiana limestone sample was negligible.

Next, thickened CO₂ in the amount of two pore volumes was injected intothe Indiana limestone. This caused a pressure drop of over 350 psi.

The Indiana limestone was then injected with a second sample of water inthe amount of over five pore volumes. This caused an additional pressuredrop of close to 100 psi. The increase in the pressure drop during thesecond water injection reflects the resistance caused by the presence ofthickened CO₂ in the porous media. After treating the formation withthickened CO₂, which blocks the high-permeable channels, the secondinjected water follows paths in the low-permeable channels.

FIG. 8 shows the efficiency of the thickened CO₂ to block thehigh-permeable channels and therefore reduce the mobility of theinjected fluids. The results showed that even after injecting a few porevolumes (less than 0.5 pore volume), the pressure drop increased, whichindicates the efficiency of the thickened CO₂.

Described implementations of the subject matter can include one or morefeatures, alone or in combination. For example, an implementation is amethod that includes the following steps. Injecting thickened CO₂ intothe top of a reservoir containing oil; forming an interface between thethickened CO₂ and the oil; mobilizing the oil; and recovering the oilwith a recovery well drilled below the reservoir.

The foregoing and other described implementations can each, optionally,include one or more of the following features:

The thickened CO₂ includes CO₂ and thickener including a copolymer ofallenether, acrylate, acrylic long carbon chain ester, acrylic longcarbon chain benzene, propylene carbonate ethyl carbonate, propyleneallyl ethyl carbonate, dimethyl carbonate, white oil, silicon, petroleumether, or a combination thereof.

The thickener has a molecular weight of 500,000 g/mol, a pH of 5.0 to8.0, a relative density of 0.90 to 1.10, a dissolution speed of lessthan about three minutes for one percent in liquid CO₂ at 25° C., or acombination thereof.

About 0.1 to 0.2 pore volumes of thickened CO₂ is injected into thereservoir.

The thickened CO₂ comprises 2 vol. % thickener and 98 vol. %supercritical CO₂.

The interface is positioned at the top of a pay zone comprisinghigh-permeable channels.

The thickened CO₂ blocks the high-permeable channels.

The thickened CO₂ is injected so that it is uniform across theinterface.

The thickened CO₂ is injected at or below the critical gas injectionrate.

The thickened CO₂ is continuously injected.

The thickened CO₂ is injected using a vertical injection well.

The thickened CO₂ is injected using a horizontal injection well.

The recovery well is a horizontal recovery well.

The recovery well is a vertical recovery well.

The reservoir pressure is below ambient pressure.

The oil is recovered using forced gravity drainage and free gravitydrainage.

The oil is mobilized with unthickened CO₂ injected into the top of thereservoir.

A second implementation is a system that includes an injection well; areservoir containing oil positioned below the injection well; thickenedCO₂; an interface between the thickened CO₂ and the oil; and a recoverywell drilled below the reservoir.

The foregoing and other described implementations can each, optionally,include one or more of the following features:

The thickened CO₂ comprises CO₂ and thickener comprising a copolymer ofallenether, acrylate, acrylic long carbon chain ester, acrylic longcarbon chain benzene, propylene carbonate ethyl carbonate, propyleneallyl ethyl carbonate, dimethyl carbonate, white oil, silicon, petroleumether, or a combination thereof.

The thickener has a molecular weight of 500,000 g/mol, a pH of 5.0 to8.0, a relative density of 0.90 to 1.10, a dissolution speed of lessthan about three minutes for one percent in liquid CO₂ at 25° C., or acombination thereof.

The reservoir comprises about 0.1 to 0.2 pore volumes of thickened CO₂.

The thickened CO₂ comprises 2 vol. % thickener and 98 vol. %supercritical CO₂.

The system has a pay zone positioned below the interface, and the payzone has high-permeable channels.

The thickened CO₂ blocks the high-permeable channels.

The thickened CO₂ is uniform across the interface.

The injection well is a vertical injection well.

The injection well is a horizontal injection well.

The recovery well is a horizontal recovery well.

The recovery well is a vertical recovery well.

The reservoir pressure is below ambient pressure.

Thus, particular implementations of the subject matter have beendescribed. Other implementations are within the scope of the followingclaims.

What is claimed is:
 1. A method for oil recovery, comprising: injectingthickened CO₂ into the top of a reservoir containing oil, wherein thethickened CO₂ comprises a thickener comprising a mixture of a copolymerwith propylene carbonate, allyl ethyl carbonate, dimethyl carbonate,white oil, silicon, oil, or petroleum ether, or combinations thereof;forming an interface between the thickened CO₂ and the oil; mobilizingthe oil with unthickened CO₂, wherein the unthickened CO₂ is injectedafter the thickened CO₂; and recovering the oil with a recovery welldrilled below the reservoir.
 2. The method of claim 1, wherein thethickener has a molecular weight of 500,000 g/mol, a pH of 5.0 to 8.0, arelative density of 0.90 to 1.10, a dissolution speed of less than aboutthree minutes for one percent in liquid CO₂ at 25° C., or a combinationthereof.
 3. The method of claim 1, wherein about 0.1 to 0.2 pore volumesof thickened CO₂ is injected into the reservoir.
 4. The method of claim1, wherein the thickened CO₂ comprises 2 vol. % thickener and 98 vol. %supercritical CO₂.
 5. The method of claim 1, wherein the thickened CO₂reduces the relative permeability of the gas in the reservoir.
 6. Themethod of claim 1, wherein the thickened CO₂ is injected so that it isuniform across the interface.
 7. The method of claim 1, wherein thethickened CO₂ is injected at or below the critical gas injection rate.8. The method of claim 1, wherein the thickened CO₂ is continuouslyinjected.
 9. The method of claim 1, wherein the thickened CO₂ isinjected using a vertical injection well.
 10. The method of claim 1,wherein the thickened CO₂ is injected using a horizontal injection well.11. The method of claim 1, wherein the recovery well is a horizontalrecovery well.
 12. The method of claim 1, wherein the recovery well is avertical recovery well.
 13. The method of claim 1, wherein the reservoirpressure is below ambient pressure.
 14. The method of claim 1, whereinthe oil is recovered using forced gravity drainage and free gravitydrainage.
 15. The method of claim 1, wherein the oil is mobilized withunthickened CO₂ injected into the top of the reservoir.
 16. A system foroil recovery, comprising: an injection well; a reservoir containing oilpositioned below the injection well; thickened CO₂, wherein thethickened CO₂ comprises a thickener comprising a blend of 50 vol. % of acopolymer comprising an acrylate with 50 vol. % of a mixture comprisingpropylene carbonate, allyl this ethyl carbonate, propylene allyl ethylcarbonate, dimethyl carbonate, white oil, silicon, or petroleum ether,or a combination thereof; an interface between the thickened CO₂ and theoil; unthickened CO₂ disposed over the thickened CO₂; and a horizontalrecovery well drilled below the reservoir.
 17. The system of claim 16,wherein the thickener has a molecular weight of 500,000 g/mol, a pH of5.0 to 8.0, a relative density of 0.90 to 1.10, a dissolution speed ofless than about three minutes for one percent in liquid CO₂ at 25° C.,or a combination thereof.
 18. The system of claim 16, wherein thereservoir comprises about 0.1 to 0.2 pore volumes of thickened CO₂. 19.The system of claim 16, wherein the thickened CO₂ comprises 2 vol. %thickener and 98 vol. % supercritical CO₂.
 20. The system of claim 16,further comprising a pay zone positioned below the interface, whereinthe pay zone comprises channels that have higher relative permeabilityto gas flow.
 21. The system of claim 16, wherein the thickened CO₂ isuniform across the interface.
 22. The system of claim 16, comprising ahorizontal injection well.
 23. The system of claim 16, comprising avertical recovery well.
 24. The system of claim 16, wherein thereservoir pressure is below ambient pressure.